IR 05000266/1999008
| ML20196D501 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 06/18/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20196D497 | List: |
| References | |
| 50-266-99-08, 50-266-99-8, 50-301-99-08, 50-301-99-8, NUDOCS 9906240289 | |
| Download: ML20196D501 (17) | |
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U.S. NUCLEAR REGULATORY COMMISSION l REGIONlil l '
Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 ;
! Report No: 50-266/99008(DRP); 50-301/99008(DRP)
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Licensee: Wisconsin Electric Power Company Facility: Point Baach Nuclear Plant, Units 1 & 2 i
Location: 6610 Nuclear Road Two Rivers, WI 54241 I
l Dates: April 11 through May 27,1999 Inspectors: F. Brown, Senior Resident inspector P. Louden, Resident inspector P. Simpson, Resident inspector Approved by: Roger Lanksbury, Chief Reactor Projects Branch 5 Division of Reactor Projects
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9906240289 990618 PDR ADOCK 05000266 G PDR t
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EXECUTIVE SUMMARY Point Beach Nuclear Plant, Units 1 & 2 NRC Inspection Report 50-266/99008(DRP); 50-301/99008(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week inspection period by the resident inspector Operations
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The inspectors identified that an operating crew failed to properly apply the licensee's procedure use and adherence policy during a Unit 1 shddown. The violation was minor because of the minimal direct safety consequence; however, the inspectors were i concerned because the involved crew had recently completed remedial training for a previous procedure violation. (Section 01.1)
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Operators performed their duties in an appropriate manner during the observed portions l of two Unit 1 startups. The approach-to-criticality evolution continued to be a licensee l strength, with thorough and focused attention being pad to critical plant parameter j (Section 01.2)
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The Unit i reactor was manually tripped on May 14,1999, due to a rupture of the 4B feedwater heater. The operators followed conduct of operations procedural requirements and exercised conservative decision-making throughout the event. The )
inspectors considered the observed performance to be particularly good. Emergency '
safety features system equipment functioned as designed. (Section 01.3)
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The licensee had initiated corrective actions to address process and cultural problems that underlay procedure use and adherence problems. However, plant material condition discrepancies and some management approved responses to these discrepancies had complicated efforts to address the cultural aspects of the procedure use and adherence problems. (Section O3.1)
Maintenance
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The licensee executed a Unit 1 mid-cycle maintenance outage to bolster reliability prior to peak summer electrical demand and as a proactive means to address material condition problems before they became a challenge to reactor operator (Section M1.1)
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The plant continued to experience secondary system failures and malfunctions that challenged plant operators and required resource intensive response and corrective maintenance. Reaction to equipment problems, while appropriate, diverted resources from desired equipment and process improvement efforts. (Section M2.1)
Enaineerina
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The inspectors identified two issues that required the licensee to revise the assessment of the frozen safety injection line event described in inspection Report 50-266/99004(DRP) and Licensee Event Report 50-266/1999-001. Other than these issues, the licensee's assessments were complete and thorough. (Section E1.1)
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- The licensee's management of commitments of issues discussed in Generic Letter 89-13, " Service Water System Problems Affecting Safety-Related Equipment,"
had not been historically aggressive. The zebra mussel control program had not been fully effective as evidenced by the discovery of zebra mussel shells in heat exchangers for two safety-related components. Problems with these programs were identified by the licensee and other external organizations in 1998. At the end of the inspection period, the licensee had begun to address the programmatic deficiencies with the zebra mussel control program and the Generic Letter 89-13 commitment issues. However, these initiatives were stillin the early stages of development and the full effectivencss could not be evaluated. (Section E2.2)
Plant Sucoort
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There were no significant plant support issues identified during this inspection perio l
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Report Details l
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Summarv of Plant Status Unit 1 began the inspection period at 100 percent power. Unit 1 was shutdown on April 23, 1999, for a planned maintenance outage. The unit was made critical on April 27 and reached 100 percent power on April 28. A rupture of the Unit 1 "4B" feedwater heater on May 14 resulted in a reactor trip. Repairs were made to the "4A" and "4B" feedwater heaters and Unit 1 was returned to 100 percent power on May 2 Unit 2 power was reduced from 100 percent to 20 percent on May 16 to allow for inspection of the "4A" and "48" feedwater heaters on that unit. Unit 2 was returned to 100 percent on May 24. Unit 2 power was decreased to 80 percent on May 26 due to an~ inoperable cross-over steam dump valve solenoid. Corrective maintenance was being performed at the end of the inspection perio I. Operations 01 Conduct of Operations t O1.1 Unit 1 Reactor Shutdown
! Inspection Scope Onsoection Procedure OP) 71707)
The inspectors observed control room activities associated with the shutdown of Unit 1 on April 23,1999, for a planned maintenance outag Observations and Findinas The unit was shutdown in a controlled and appropriate manner, using prescribed procedures. The inspectors identified two issues which were addressed by the license The first issue involved a request by a senior reactor operator (SRO) that a quality assurance (QA) specialist not enter the control room while a shift turnover was being 3 performed during the shutdown. The QA specialist left the control room without comment. The inspectors discussed this observation with the operations manager after the completion of the turnover. The operations manager indicated that it was his j expectation that QA specialists would have full access to areas that they were auditing or observing. The operations manager later conveyed this expectation to the involved SRO and the QA specialis The second issue involved procedural adherence. The shutdown procedure specified that steam generator blowdown be realigned. The realignment instructions were contained in Operating Instruction (01) 14, " Steam Generator Blowdown Operation," .
Revision 14, a procedure required by Technical Specification (T/S) 15.6.8. When the auxiliary operator (AO) in the plant attempted to perform the new alignment, one of the valves which was to be closed per Step 4.8.7 was found to be stuck open (due to galled stem threads). The AO called the control room for instructions on how to proceed. The j licensee's procedure adherence instruction, Operations Manual (OM) 1.4, "Use of Operations Group Procedures and Work Plans," Revision 1, stated that procedures that could not be performed as written were to be changed prior to proceeding with the work j
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evolution. Contrary to the guidance contained in Operations Manual OM 1.4, the duty operation supervisor (an SRO) in the control room directed the AO to proceed with the next step (4.8.8) because the " intent" of the step to close the valve had been met by the action of closing other valves listed in 0114. The operating supervisor (another SRO)
was aware of the actions being taken but did not comment on the inappropriateness of proceeding with the procedure. The failure to operate the plant in accordance with approved procedures was a violation of T/S 15.6.8. This violation was of minor safety significance and, consistent with Section IV of the Enforcement Policy, is not subject to formal enforcement action; however, ths violation was of concern to the inspectors for three reasons. First, procedural adherence issues have been the subject of numerous '
enforcement actions over the previous two years. Second, the crew involved with this violation had recently completed remedial training following a previous case of ;
procedural noncompliance. Third, the violation was not identified until the inspectors
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brought the issue to the attention of station management. This violation is in the i licensee's corrective action program as Condition Report (CR)99-127 j Conclusionc The inspectors identified th?t an operating crosu failed to properly apply the licensee's procedure use and adherence policy during a Unit 1 shutdown. The violation was minor because of the minimal direct safety consequence; however, the inspectors were concerned because the involved crew had recently completed remedial training for a ;
previous procedure violatio l 01.2 Unit 1 Reactor Startuo Inspection Scope (IP 71707)
The inspectors observed control room activities associated with the startup of Unit 1 following the completion of a planned maintenance outage and an unplanned outage for repair of degraded feedwater heater Observations and Findinas Operations management and reactor engineering personnel were present during the two reactor startups. The operating supervisor provided adequate oversight of the reactor operators Procedures were in active use in the control room. Three-part communication was generally used. Reactivity manipulations were conducted in a controlled and deliberate manner. Reactor engineers and duty technical advisors provided appropriate support to operators. The operators conducted the approach to criticality in a thorough anJ focused manner, consistent with previous inspector observation During the Unit 1 startup from the planned outage, control rod misalignment alarms from the plant process computer system were frequently received. Response to these alarms resulted in multiple entries into T/S action statements and in one instance also required entry into Abnormal Operating Procedure AOP 68, " Stuck Rods." The inspectors verified that the crew properly complied with the T/S action requirements and correctly implemented the applicable portions of AOP 68. Similar problems during a previous startup were documented in Section 01.2 of Inspection Report (IR)
50-266/99002(DRP); 50-301/99002(DRP). The licensee concluded that the alarms were
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i caused by temperatuf6 induced variations in the magnetic coupling of the rod position indication system and were not valid indications of out-of-position rod For the Unit 1 restart following the forced outage, the operating crew and reactor engineer developed a plan for responding to plant process computer system " rod misalignment" alarms. The approach was slightly different from the approach used by other operating crews dunng previous startup evolutions. The inspectors considered both approaches appropriate, but were concerned by the lack of consistency and the apparent lack of clear expectations for operator response to this alarm during startup The duty shift superintendent (the lead SRO onshift) subsequently told the inspectors that a procedure feedback form would be submitted to request clear guidance on the appropria'e response 10 this expected alar Conclusions Operators performed their duties in an appropriate manner during the observed portions of two Unit 1 startups. The approach-to-criticality evolution continued to be a licensee strength with thorcugh and focused attention being paid to critical plant parameters.
01.3 Unit 1 ReacioLT.np and Safety iniection (SI) Followina "4B" Feedwater Heater Ruoture Inspection Scope (IP 71707)
The inspectors observed and reviewed plant and operator responses to a feedwater heater shell rupture which occurred on May 14,1999. The rupture led to the eventual manual tripping of the Unit 1 reactor followed by a manual cctuation of the emergency safety features syste Observations and Findinas
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At approximately 7:10 a.m. on May 14,1999, while traversing the Unit 1 turbine building, the inspector observed the rupturing of the Unit 1 "4B" feedwater heater vessel. The inspector then responded to the control room upon the site announcement of a Unit 1 reactor tri The operators manually tripped the Unit i reactor at 7:13 a.m., in part because they did not know the extent of the secondary side system damage. Following the reactor trip, steam generator level " shrink" reached the actuation set point (25 percent level) for the auxiliary feedwater (AFW) system. The turbine- and motor-driven AFW pumps started on demand and fed water to the steam generators. The addition of this much cooler water on the secondary side caused cooling induced pressure reduction in the reactor l coolant system and lowered pressurizer level. The operators noted that pressurizer level had decreased to 11 percent and was continuing to decrease. Operators manually actuated the SI system prior to rt . ching the manual Sl criterion of 10 percent pressurizer level specified in the emergency operating procedure All safety systems functioned as designed follov.ing the emergency safety features actuation, and the plant was stabilized by the operators. The lowest reactor coolant system pressure observed was 1750 pounds per square inch gauge. This was well i
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above the Si pump cutoff head; therefore, no injection into the vessel occurred. The
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' operators proceeded through the emergency operating procedures and maintained the j plant in the hot shutdown conditio The inspectors observed control room operators after the trip and concluded that they responded to alarms and indicated parameters in an appropriate manner. The reactor !
operators and SROs used clear, consistent, three-way communications throughout the analysis of and recovery from the trip. The duty shift superintendent exhibited excellent l command and control oversight. Extra reactor operators were in the control room to !
assist the on-shift crew, and were efficiently used to evaluate equipment damage and .
- contingencies actions. Overall, the inspectors concluded that the operators involved l
- . with the event maintained conduct of operations standards, displayed conservative decision-making, and exhibited good teamwork in evaluating the problem !
A review of emergency actions levels indicated that no emergency classification was entered. Tha inspectors independently reviewed the emergency action levels and i reached the same conclusion. A 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency report was made to the NRC for emergency safety features actuations in accordance with 10 CFR Part 50.72(b)(2)(ii). ,
Licensee management formed a root cause team to evaluate the event, assess the l l plant and operator response, and identify the failure mechanism of the "4B" feedwater 1
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heater shell. At the conclusion of the inspection, the licensee's root cause assessment l
was not complete. Pieces of the failed heater shell had been sent to a materials analysis Icboratory to determine the cause of the feedwa%r heater rupture. The licensee's actions to assess and identify additional issun regarding this event was in the corrective action program as Root Cause Evaluation 99-078 and CR 99-1340.
l Conclusions I The Unit 1 reactor was manually tripped on May 14,1999, due to a rupture of the 48
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l feedwater hester.' The operators followed conduct of operations procedural
requirements and exercised conservative decision-making throughout the event. The inspectors considered the observed performance to be particularly good. Emergency
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safety features system equipment functioned as designe Operations Procedures and Documentation i
! 03.1 Procedure Use and Adherence Culture l
L Insoection Scope (IP 71707)
l Several enforcement actions had been issued for the failure to have or use appropriate procedures at Point Beach over the past 2 years, in addition, procedure use and adherence had been discussed at several meetings between NRC and licensee management. The licensee had indicated that programmatic and cultural issues were being addressed in an effort to improve procedure use and adherence. The in'spectors monitored the licensee's corrective action '
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1 Observations and Findinas During this inspection period, the licensee informed the inspectors of program and process changes that had been made or were in the planning process. The inspectors concluded that these changes appeared to be appropriate and potentially effective. The licensee also discussed the need to create a new procedere adherence culture with the operator Based on CRs generated by plant staff and conversations with operators (and other plant staff), the inspectors identified at least two issues that were complicating the licensee's efforts to address the cultural problem. The first issue was that many of the ;
equipment failures discussed in Section M2.1 of this report were not addressed by l approved plant procedures. The inspectors concluded that these failures created the l perceived need for operators to take actions that were not prescribed by plant I procedures. For instance, there was no approved procedure for recovering from an Si l initiation. Because of this, operators felt compelled to selectively perform steps in I various system checklists and operating procedures during the post-SI recovery on May 14,1999. This practice was not consistent with st&ted management expectations for procedure usage. The second issue was that some aspects of management i approved responses to material condition problems were perceived by plant staff to be non-conservative and inconsistent with the stated expectations for procedure use and :
adherence, For instance, during the Unit 2 down-power to investigate the condition of !
the "4A" and "4B" feedwater heaters, the Manager's Supervisory Staff (onsite review committee) approved a plan to perform extraction steam system valve line-up changes l to a work plan rather than an approved procedure. This created a situation wherein an l proved and reviewed procedure for the extraction steam system was modified by a ak plan which did not require the same level of review and approval. Significant p oblems in completing the task, including repeated system water hammers, were experienced while the work plan was in us Conc!qsions The licensee had initiated corrective actions to address process and cultural problems that underlay procedure use and adherence problerns. However, plant material ;
[ condition discrepancies, and some management approved responses to these i discrepancies, had complicated efforts to address the cultural aspects of the procedure use and adherence problem ,
ll. Maintenance M1 Conduct of Maintenance M1.1 Unit 1 Maintenance Outage Inspection Scope (IPs 62707 & 71707)
The inspectors observed and reviewed portions of selected activities associated with a planned maintenance outage for Unit . Observations and Findinas On April 23,1999, the licensee commenced a mid-cycle maintenance outage for Unit l Major work completed during the outage included repair of a control rod drive
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mechanism cooling fan, main generator motor operated disconnect repair, secondary system valve repairs, and condenser waterbox cleaning. The licensee chose to perform key work on the unit prior to the summer in order to bolster reliability throughout the peak-demand summer month The licensee successfully coped with several emergent items during the course of the I outage resulting in minimal schedule impcct. The "A" motor driven AFW pump developed a leak in its minimum flow recirculation line. The interlock on the upper containment personnel hatch failed which disabled the outer door and prevented the airlock's us On April 28.1999, the licensee returned Unit 1 to service. Two days later, on April 30, the licenses conducted a post-outage critique in order to generate lessons learned to ,
feedback into future work pluring and executio j 1 Coaclusi_o_ns The licerisee executed a Unit 1 mid-cycle maintenance outage to bolster reliability prior to peak summer electrical demand and as a proactive means to addrecs material condition problems before they became a challenge to reactor operator l M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Material Condition issues Continued to Cause Challenaes to Operators l Inspection Scope (IPs 71707. 62707. & 61726)
The inspectors monitored plant material conditions issues, the effects of these issues on operators, and the licensee's response to the issue Observations and Findinas Numerous secondary system equipment failures or malfunctions challenged the normal operation of the facility during this reporting period. Examp;es included:
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Throughwall leaks at welded joints in the minimum flow lines caused motor-driven feedwater pumps P-38A and P-38B to be removed from service on April 24,1999, and May 24,1999, respectively. A similar throughwall leak had occurred in the P-38A minimum flow line (at a different weld joint) in June 199 The licensee was evaluating the apparently generic aspects of these failures under CR 99-139 The failure of the Unit 1 feedwater heater "4B" resulted in a manual plant trip and manual Si injection. At the conclusion of the inspection period, the licensee had not yet determined why the plant trip had resulted in a primary system cooldown of such magnitude that manual SI was required. A root cause evaluation of the event was being performe '
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A power increase for Unit 2 was delayed by the malfunction of a heater drain tank dump valve,2 FD 2532A. Corrective maintenance identified foreign material that appeared to be affecting the valve's operation. The valve was returned to service prior to power ascensio *
A Unit 1 shutdown and Unit 2 power increase were delayed by material condition l problems in the steam generator blow down systems. Problems included !
inoperable isolation valves and a failed blow down tank rupture disk. Corrective
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maintenance was completed for each inoperable component that directly affected plant operatio *
Unit 2 power was decreased to 80 percent on May 26,1999, due to an inoperable cross-over steam dump relay, Corrective maintenance was being performed at the end of the inspection perio *
The voltage regulator for one of the redundant Unit 1 control rod drive motor l generator sets (1G-06) failed low on May 24,1999. Removal of 1G-06 from l service with the Unit at power was a first-time evolution that created the potential I for operator challenge and unanticipated response from the rod drive control i system. Corrective maintenance was being planned at the end of the inspection !
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The steam generator feedwater pumps and feedwater piping for both units continued to be subject to flow-induced vibration that the inspectors considered i to be excessive; however, instances of vibration-induced feed pump failures I seen in previous inspection periods did not occur during this perio The licensee took appropriate corrective action for malfunctions and failures that directly affected plant operations. The licensee also expressed satisfaction in the backlog reduction efforts for corrective and preventive maintenance items. While not discounting the licensee's response to material condition problems, the inspectors were concerned that the number of operational challenges continued to be higher than necessary. While none of the challenges to date had been significant from a nuclear safety perspective, they did tax the resources of the operations, engineering, maintenance, and planning organizations. These resources were diverted from routine activities as well as from long-term hardware and process improvement initiative The inspectors continue to monitor the effectiveness of the 'icensee's preventive maintenance and corrective action programs using routine inspection procedures. The inspectors had not identified any significant weaknesses in required programs through the end of the inspection perio c. Conclusions The plant continued to experience secondary system failures and malfunctions that challenged plant operators and required resource-intensive response and corrective maintenance. Reaction to equipment problems, while appropriate, diverted resources from desired equipment and process improvement effort y
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! Ill. Enaineerina j E1 Conduct of Engineering E1.1 Follow-up of Frozen SI Recirculation Line Inspection Scoce (IP 37551)
The inspectors participated in a predecisional enforcement conference, reviewed licensee event reports (LERs), and followed licensee corrective actions for the frozen Si recirculation line documented in IR 99-266/99004(DRP) and the associated Notice of Violation dated A'p ril 28,1999, Observations and Findinas The licensee's assessment of the frozen Si recirculation line was presented during a pre-decisional enforcement conference and in Supplements -01 and -02 to LER 50-266/1999-001. The assessments were generally thorough and complete; however, the inspectors identified two issues that the licensee had failed to conside )
i The first issue dealt with the need to consider the effect of postulated boundary valve 1 leakage during large break loss-of-coolant accidents. The inspectors identified this ]
issue through review of the existing facility accident analysis description of the Si system. Licensee analysis performed up until that time had been focused on small-break accident scenarios. The licensee concurred with the inspectors' finding and incorporated the appropriate evaluation into LER 50-266/1999-001, Supplement -0 The second inspector-identified issue dealt with the potential for leakage in floor drain isolation valves which isolated residual heat removal pump cubicles from the auxiliary building sump. Licensee evaluations had taken credit for these valves providing positive i isolation during a postulated flood associated with the frozen Si line. The inspectors l had observed ground water draining through one of the lines which was assumed to be j isolated by a valve and questioned the licensee's basis for taking credit for the valve The licensee tested the valves and found that the valve for one of the two Unit 1 cubicles, and the valves for both the Unit 2 cubicles, leaked. The licensee included revised flooding analysis in LER 50-266/1999-001, Supplement -02. The licensee also initiated corrective work orders for all four drain line isolation valve i 1 Conclusions The inspectors identified two issues that required the licens6s to revise the assessment of the frozen Si line event described in IR 50-266/99004(DRP) and LER 50-266/1999-001. Other than these issues, the licensee's assessments were complete and thoroug E2 Engineering Support of Facilities and Equipment E2.1 System Enaineerino Sucoort of Operations and Maintenance Activities The inspectors noted good system engineer involvement in several operations and maintenance activities during this inspection period. Those activities included the Unit 1 11 ,
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l On April 1,1999, a system engineer identified that Unit 1 condenser vacuum was I noticeably higher than that of Unit 2. The resultant caus,e was determined to be zebra l musselintrusion fouling of the Unit imain condenser and condensate cooler. This event I plus the recent circulating water forebay cleaning which removed 60 cubic yards of !
zebra mussel shells, prompted the inspectors to review the licensee's program to l monitor and control macroscopic bio-fouling (zebra musselinfestation) of the service water system (SWS). The inspectors also reviewed the licensee's responses and actions taken to address NRC Generic Letter (GL) 89-13, " Service Water System Problems Affecting Safety-Related Equipment." Observations and Findinas l GL 89-13 Resoonse
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Generic Letter 89-13 details several problems which could affect the operability of the SWS at power plants. One of the areas of concern involves macroscopic bio-fouling of the service water intakes and piping. The species of concern for plants which use Lake Michigan as a service water supply source are zebra mussels. Generic Letter 89-13 and its enclosures provided guidance on acceptable monitoring and control program
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components which would ensure that the heat removal requirements of the SWS were satisfie The inspectors reviewed the licensee's response to the GL 89-13 issues. At the time of the response (1990), zebra mussel fouling had not been observed at the plant; however, it was recognized that mussels (based on migration) would impact the plant within a few years. Therefore, the response was mostly forward looking in nature, addressing planned actions rather than ongoing observation and control methods employed at that time. The response, in part, included commitments to semi-annually inspect the intake structure, inspection of the entire forebay every two years, use of chlorination system for the forebay, and heat exchanger performance monitorin The inspectors reviewed the licensee's program to monitor and control zebra mussels following the identified presence of mussels in the circulating water forebay in 199 The licensee established routine chlorinations of the forebay. Routine cleanings of the circulating water forebay to control zebra mussel infestations were periodically performed. In addition, chlorine dioxide chemical treatments have been performed three times since the identification of zebra mussels in the foreba Even though the s.forementioned efforts were undertaken to control zebra mussel infestation, discoveries of zebra mussel shells in safety-related heat exchangers (as discussed below) have called into question the effectiveness of the control progra The main contributor to deficiencies in the program was determined to be the lack of a single responsible individual to ensure that effective monitoring was being performed
and that the various departments involved were kept apprised of the program's effectivenes The inspectors also noted that the original GL-89-13 plans did not thoroughly address all the programmatic aspects described in the GL recommendations for a minimally {
acceptable program. Specifically, the effectiveness of the chlorination activities were l not formally reviewed and evaluated, and stagnant systerns, such as fire protection l lines, were not placed in "layup" with chlorinated wate l l
Furthermore, a thorough review of issues discussed in GL 89-13, Supplement 1, did not '
appear to have been performed to assess plant specific issues. Once zebra mussels were identified as a concern at the station, a retrospective review of the commitments j made in the original response to GL 89-13 was not performe Observed Effects of Zebra Musselintrusion on Safety-Related Systems In May 1997, during a routine overhaul of the Unit 1 Train "A" emergency diesel generator (EDG), zebra mussel shells were found in the diesel cooling heat exchanger endbells. This discovery led to declaring the Unit 2 Train "A" EDG inoperable due to the potential common mode failure (zobra mussel shell intrusion and flow blockage).
In response to the discovery of zebra mussel shells in the EDG heat exchanger endbells, the licensee conducted radiography of the heat exchanger endbells on a quarterly basis, and a modification was planned to place strainers in the service water supply lines to the EDG cooler In May 1998, zebra mussel shells were found in portions of the Unit 1 "C" and "D" containment fan cooler heat exchangers. The affected cooling lines had exhibited degraded heat transfer performance. The lines were subsequently backflushed to eliminate the blockage. A periodic inspection program was established to quarterly monitor potential containment fan cooler degradation via infrared temperature scanning of the cooler The inspectors discussed with system engineers the scope of potential fouling of the emergency service water supply lines to the AFW pumps. The licensee performeo a monthly flush of the service water supply to the AFW system per Operations Periodic Check (PC) 43, Part 5, " Service Water to Auxiliary Feedwater Pump Line Flush, Monthly," Revision 4. However, the inspectors noted that the flush was of the common service water header supply line and did not include the individual supply lines for each of the AFW pumps. System engineers indicated that a few mussel shells had been found but a concern did not exist. The engineers added that sand and sitt was more of a concern for those particular lines. Discussions with auxiliary operators who perfocmed the PC 43 Part 5 indicated that sand and silt was noted during the monthiy flushings, but typically cleared by the end of the flushing time (30 minutes). At the end of the inspection period, the inspectors were attempting to obtain the licensee's documented evaluation that the known level of periodic silt build-up in the safety-related service water supply to tha AFW pumps did not pose a challenge to pump operabilit . . l gensee Self-Assessment of the Zebra Mussel Control Prooram The licensee conducted a self-assessment of the SWS in June 1998 to review various
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SWS concerns including the implementation of GL 89-13 commitments. The
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assessment cculuded that compliance with long-term regulatory commitments relative to GL 89-13 was weak. Heat exchanger performance trending was determined to be informal. Information regarding the identification of zebra mussels in safety-related systems was not used to evaluate and make changes to the chlorination process. In addition, other program reviews by external organizations identified that the zebra mussel control program was uncoordinated and ineffectiv Current Licensee Actions in response to the SWS self-assessment findings and the observations from external organi?.ations, the licensee developed an action plan to address the identified weaknesses in the zebra mussel monitoring and control program. These actions included, in part, the designation of a program coordinator, more active involvement in the corporate zebra mussel task force, increased frequency of chlorinations, the development cf programmatic procedures, and the evaluation of other technologies to control zebra musseiinfestation. In addition, a system engineer was assigned to review and evaluate the licensee's original commitments pertaining to GL 89-13 and recommend changes or corrective action Most of these activities were in the development stage at the time of the inspection. The program coordinator was still developing action plans and project documentation st the conclusion of the inspection period. The GL 89-13 review was only partially complete' ,
however, several discrepancies had been identified and entered into the corrective action system (CR 99-1425). Due to the infancy of these actions, the long-term effectiveness could not be determine Conclusions The licensee's management of commitments regarding GL 89-13 issues had not been historically aggressive. The licensee's zebra mussel control program had not been fully effective as evidenced by the discovery of zebra mussel shells in heat exchangers for two safety-related components. Problems with this program were identified by the licensee and other external organizations in 1998. At the end of the inspection period, the licensee had begun to address the programmatic deficiencies with the zebra mussel control program and the GL 89-13 commitment issues. However, these initiatives were still in the early stages of development and the full effectiveness could not be evaluate E8 Miscellaneous Engineering issues ;
E8.1 LC!csod) LER 50-266/99001-01: Safety injection recirculation line to RWST [ Refueling 4 Water Storage Tank] frozen. This supplement provided additional licensee corrective l actions and safety assessment. Inspector-identified issues are discussed in Section l E1.1 of this repor j E8.2 (Closed) LER 50-266/99001-02: Safety injection recirculation line to RWST [ Refueling Water Storage Tonk] frozen. The reasons for this supplement are discussed in i Section E1.1 of this repor : .. A
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E8.3 (Closed) Violation (VIO) 50-266/99004-02 Failure to address the low temperature of a safety-related pipe. The corrective actions associated with this violation were provided
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in LER 50-266/99001, and were considered to be appropdate, as discussed in the cover I letter, dated April 28,1999, which transmitted the Notice of Violation l
IV. Plant Sugnort j R1 Radiological Protection and Chemistry Controls R General Comments flP 71750)
i During this inspection period, the inspectors conducted frequent tours of the radiologically controlled area. No significant problems were observed with radiological -
postings or controls. The inspectors did identify an occasion where two detailed survey .
maps for a high radiation area attributed significantly different dose rate readings to !
known hot spots. One of the maps was dated as having been performed prior to a recent change in plant conditions. This discrepancy was reported to the licensee for j corrective actio j l
l V. Manaaement Meetinas l X1 Exit Meeting Summary l
The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 27,1999. The licencee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie X3 Management Meeting Summary On May 4,1999, a management meeting was conducted in Lisle, Illinoic at the Reg;on ill office complex. The senior regional management of Region ll1 attended. An open and frank ,
discussion with the licensee was heki, concerning the following topics: j i operations leadership focus plant operations update raaintenance update l
' engineering progiam status 5 corrective action program procedure upgrade program i
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l PARTIAL LIST OF PERSONS CONTACTED I
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Wisconsin Elg.q tric Power Company l l
y M. E. Reddemann, Site Vice President
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R. G. Mende. Plant Manager l J. R. Anderson, Operations Manager: ;
D. P. McCloskey, Maintenance Manager !
. R. P. Farrell, Radiation Protection Manager L .V. M. Kaminskao, Regu!atory Services and Licensing Manager l q
L C. R;Peterson, Director of Engineering ,
< J. G. Schweitzer, System Engineering Manager NRC l B. A. Wetzel, Poira Beach Project Manager, NRR l
INSPECTION PROCEDURES USED I IP 37551: Onsite Engineering IP 61726: Surve!! lances IP 62707: Maintenance Observations IP 71707: . Plant Operations
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ITEMS OPENED, CLOSED, AND DISCUSSED Ocened Norm C!osed 50 266/99001-01 LER Safety injection racirculation line to RWST (Refueling Water Storage Tank) frozen 50-2S6/99001-02 LER Safety injection recirculation line to RWST (Refueling Water Storage Tank) frozen 50-266/99004-02(DRP) VIO Failure to address the low temperature of a safety-related
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pipe Qi:icrue_d l None i
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. LIST OF ACRONYMS USED l AFW Auxiliary Feodwater
_ AO Auxiliary Operator CFR Code of Federal Regulations CR Condition Report DRP. Division of reactor Projects EDG Emergency Diesel Generator >
GL Generic Letter ,
IP inspection Procedure l
'IR inspection Report LER Licensee Event Report NRC Nuclear Regulatory Commission 01 Operating instruction OM Operations Manual PC Operations Periodic Check QA Quality Assurance SI- Safety injection SWS Service Water System SRO Senior Reactor Operator T/S Technical Specification VIO Violation i
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